Results for Half Year Ended 30 June 2026

London, 9 September 2026 - Energean plc (LSE: ENOG, TASE: אנאג) is pleased to announce its half-year results for the six months ended 30 June 2026 ("H1 2026").

Highlights:

• Strong recovery since the re-start of production in Israel and increase in liquids revenues.
• Reduction in net debt and cash cost of production and increase in free cash flow.
• As operator, Energean has commissioned the second oil train, completed the first Katlan heavy-lift and drilled and completed two deepwater development wells.
• Egypt concession merger terms agreed, enhancing cash flow and unlocking new growth opportunities.
• ~$1.4 billion new GSPA signed with Sorek, demonstrating gas demand growth in Israel.

Mathios Rigas, Chief Executive Officer of Energean, commented:

"Energean has entered the second half of 2026 from a position of real strength. Free cash flow rose 35% year-on-year to $250 million in H1 2026, profit after tax increased 45% to $160 million, and net debt fell by $97 million in Q2 2026, all while we are in the peak year of investment for Katlan. Group production reached levels over 180 Kboe/d in August[1] following the restart of production in Israel, and we remain on track to deliver full year guidance of 130-140 Kboe/d[2].

"Operationally, our teams in the year so far have delivered three major milestones in parallel: commissioning the second oil train on the Energean Power FPSO, which lifted liquids processing capacity by 72%; completing the first Katlan heavy-lift campaign; and drilling and completing two Katlan deepwater development wells, marking progress on the critical path towards first gas from the Katlan project in H1 2027.

"In Egypt, the payment environment has improved markedly, with our net receivables now at their lowest level since 2020. We have agreed the principal terms with EGPC to consolidate our Abu Qir, North El Amriya and North Idku concessions into a single concession with improved fiscal terms. It is under these new terms that we will invest an initial $150 million over the next four years with a target to double production and reserves. It also unlocks new exploration acreage, estimated to contain >4 Tcf[3] of exploration potential.

"We are also laying the foundations for future growth through a new ~$1.4 billion gas sales and purchase agreement ("GSPA") with Sorek, continued progress on key milestones at Irena in Croatia and the Nitzana export pipeline, which remain on track respectively for first gas in H1 2027 and completion in late 2028, and preparations for exploration drilling at Block 2 in Greece with ExxonMobil, which is due to begin in Q2 2027. We also remain disciplined and focused on delivering transformational growth across EMEA, concentrated on those that strengthen and diversify our production base, enhance cash flow generation and support deleveraging."

Financial results summary

H1 2026 review:

Strong recovery since the re-start of production in Israel and increase in liquids revenues

• Consistent with previous 2026 updates, performance during the period was impacted by the 41-day government-mandated suspension of production in Israel caused by the regional conflict and lower production from Cassiopea in Italy, resulting in Group average working interest production of 124 Kboe/d[9] (H1 2025: 138 Kboe/d) and sales volumes[10] of 20.17 mmboe (H1 2025: 22.81 mmboe).

o Production has subsequently recovered strongly, with 8-months 2026 production averaging 135 Kboe/d, in line with full-year guidance of 130-140 Kboe/d[11], supported by robust August standalone production, which reached levels over 180 Kboe/d during the month[12].

• Total revenue from production activities was $743 million (H1 2025: $804 million) and adjusted EBITDAX was $478 million (H1 2025: $505 million). The reduction in sales volumes was partly offset by a 29% increase in realised liquids prices, which drove a 14% year-on-year increase in liquids revenues to $267 million[13] (H1 2025: $234 million).
• Profit after tax was $160 million, up 45% year-on-year (H1 2025: $110 million), reflecting a lower effective tax rate primarily driven by the recognition of previously unrecognised deferred tax assets in Italy.

Egypt concession merger terms agreed, enhancing cash flow and unlocking new growth opportunities

• Post-period end, Energean reached agreement with EGPC on the principal concession terms to consolidate its Abu Qir, North El Amriya and North Idku concessions into a single concession, subject to parliament ratification.
• The new concession terms include enhanced fiscal terms and improved gas pricing, which are expected to strengthen project economics and increase long-term cash flow generation.
• Energean will commit an initial $150 million of near-field development and exploration investment over a four-year period, which, subject to exploration success, could add up to 50 mmboe in aggregate and double production over the following decade. It also unlocks new exploration acreage, estimated to contain >4 Tcf[14], which includes approximately 3 Tcf of gas in the deep horizon.
• The agreement reflects Egypt's increasingly supportive operating environment, including record-low receivables levels and continued government backing for upstream investment, and reinforces Egypt as a core country within Energean's Mediterranean portfolio.

Executing the next phase of organic growth

• Demonstrating continued strong domestic gas demand in Israel, Energean signed a ~$1.4 billion GSPA with Sorek post-period for the supply of gas to its new H-class power station. The agreement is for the supply of up to 0.5 bcm/yr from late 2029, increasing to up to 0.6 bcm/yr from September 2035 and includes interruptible volumes during the summer months between late 2029-2035. The contract contains floor pricing, take-or-pay and price indexation provisions.
• Production and development capital expenditure was $350 million (H1 2025: $299 million) and up 17% year-on-year, reflecting the peak year of expenditure on the Katlan project.

o Significant progress was made on the Katlan development across drilling, subsea and FPSO upgrade workstreams during the period, with first gas on track for H1 2027. Expenditure on Katlan totalled $267 million[15] during the period, bringing cumulative spend to just over 60% of the $1.2 billion Final Investment Decision ("FID") amount.

o Commissioning of the second oil train project was safely completed post-period end, increasing liquids handling capacity from 18 kbbl/d to 31 kbbl/d.

o The Nitzana export pipeline and Irena development continue to advance on schedule and on budget towards their targeted completion and start-up milestones in late 2028 and H1 2027, respectively.

• Exploration activities continued to advance, with drilling underway on the East Bir El-Nus ("EBEN") exploration well in Egypt and preparations ongoing for the Block 2 exploration well with ExxonMobil in Greece, the latter which is expected to spud in Q2 2027 and is targeting ~9.5 Tcf of gross Pmean GIIP[16].

Inorganic growth opportunities under active review

• The Group is actively assessing growth opportunities across the EMEA region, including in its existing countries of operations.
• Energean's M&A strategy remains focused on long-term growth and diversification, underpinned by strict capital discipline, an intention to reduce leverage over time and a focus on enhancing cash flow generation and shareholder returns.
• During the period, the Group announced the proposed acquisition of interests in certain offshore Angola assets. In August 2026, the Group was notified that Etu Energias had executed a sale and purchase agreement pursuant to its contractual pre-emption rights with respect to the Group's proposed acquisition of Chevron's interests in Blocks 14 and 14K, offshore Angola. As of the time of writing, the sale and purchase agreement between Energean and Chevron remains in effect until the sale and purchase agreement between Chevron and Etu Energias has been completed.

Reduction in net debt and Cost of Production and increase in free cash flow

• Cash cost of production[17] was $259 million (H1 2025: $272 million), down 5% year-on-year, primarily reflecting lower production-related operating expenditure in Israel. Excluding royalties, operating costs were $162 million (H1 2025: $175 million).
• Cash flow from operating activities was $476 million (H1 2025: $555 million), down 14% reflecting the operational impacts described above, somewhat offset by strong collection of trade receivables in Egypt, whereby net receivables (after provision for expected credit loss) reduced to $75 million as at 30 June 2026; the lowest balance recorded since Energean acquired the Edison E&P portfolio in 2020.
• Free cash flow[18] of $250 million (H1 2025: $185 million), up 35%, as lower cash capital expenditure of $250 million (H1 2025: $385 million) offset the reduction in cash flow from operating activities.
• Total liquidity of $404 million at 30 June 2026, comprising cash and cash equivalents and restricted cash of $321 million and $83 million of available liquidity facilities. Total liquidity increased by $114 million since 31 March 2026 ($290 million), reflecting higher cash balances.
• Net debt of $3,227 million, down $28 million since 31 December 2025 ($3,255 million) and $97 million since 31 March 2026 ($3,325 million), reflecting lower total borrowings. Leverage was 3.0x at 30 June 2026 (31 December 2025: 2.9x; 31 March 2026: 3.2x), with the increase versus year-end reflecting lower adjusted EBITDAX for the reasons outlined above.

Outlook:

• All full year 2026 guidance re-iterated (refer to '2026 guidance' table below), except for exploration and decommissioning expenditure, both of which have been reduced.

o Strong post-period production performance, supported by the contribution of the second oil train, reinforces management confidence in delivering full year 2026 guidance.

• Q2 2026 dividend of 10 US cents/share declared today and expected to be paid on 30 September 2026.
• Energean expects to refinance its 2028 Energean Israel Limited bond and is evaluating a range of options.
• Parliamentary ratification of the Egypt concession merger expected by mid-2027, with the new concession terms targeted to become effective on 1 January 2027.
• First gas from Katlan in H1 2027.
• Commencement of Block 2 drilling in Greece in Q2 2027, targeting ~9.5 Tcf of gross Pmean GIIP[19].
• Active pipeline of transformational M&A opportunities under evaluation in the EMEA region, including within its existing countries of operations, to support long-term growth, underpinned by strict capital discipline.

Online Results Presentation

Management will host a live online presentation today at 08:30 BST / 10:30 IDT. Registration details can be accessed via the following link: https://energean-hy-2026-results.open-exchange.net/.

The presentation slides will be published on Energean's website at www.energean.com ahead of the live event. A replay of the webcast will be available after the event.

Effective from January 2026, the Group expanded the scope of its Health and Safety KPI reporting. In addition to employees and contractors at Energean-operated sites and premises in Israel, Italy and Greece, the reporting boundary now includes: the AQP Joint Venture ("JV") in Egypt, the Edina JV in Croatia, the Alba Marina and Leonis Floating, Storage and Offloading ("FSO") vessels in Italy, and the Energean Star Floating Storage Vessel ("FSV") in Israel. Comparative H1 2025 metrics have been restated accordingly.

In H1 2026, the Lost Time Injury Frequency ("LTIF") Rate was 0.00 (H1 2025: 0.408) and the Total Recordable Incident Rate ("TRIR") was 0.242 (H1 2025: 0.408), an improvement versus the prior year and well below the Group's full year targets of <0.55 and <1.10.

Scope 1 and 2 emissions intensity on an equity share basis was 8.1 kgCO2e/boe, down 2% year-on-year (H1 2025: 8.3 kgCO2e/boe) due primarily to lower levels of non-routine flaring.

Production and Operational Update

Summary

Group average working interest production[20] was 124 Kboe/d (83% gas) in H1 2026, down 10% year-on-year. This was largely driven by two factors: (1) the temporary suspension of production in Israel for 41 days between 28 February and 9 April 2026, following a directive from the Ministry of Energy and Infrastructure due to geopolitical escalations and (2) Cassiopea performance (refer to the 'Europe' section below). Output from Israel was subsequently restored and Group production averaged 135 Kboe/d in the eight months to 31 August 2026, in line with the Group's full year 2026 production guidance of 130-140 Kboe/d[21], exceeding levels of 180 Kboe/d in August 2026[22].

This table may not cast due to rounding.

Israel

Production

In H1 2026, production from Israel averaged 87 Kboe/d (88% gas), 7% down year-on-year (H1 2025: 94 Kboe/d). Production was impacted by the temporary suspension of operations for 41 days between 28 February and 9 April 2026, following a directive from the Ministry of Energy and Infrastructure in response to regional geopolitical developments. Excluding this period of mandated shutdown, production averaged 112 Kboe/d, in line with the Group's original full year 2026 production guidance range for Israel of 108-114 Kboe/d.

FPSO uptime (excluding planned shutdowns and Ministry ordered suspensions) averaged 99% for the 6-months to 30 June 2026 (H1 2025: 97%).

Gas sales

During H1 2026, Energean sold 2.13 bcm of gas into the domestic Israeli market, compared with 2.29 bcm in H1 2025. Of this, 1.97 bcm was sold under its long-term gas sales agreements (H1 2025: 2.21 bcm) and 0.16 bcm was marketed through spot sales (H1 2025: 0.08 bcm).

Post-period end, in September 2026, Energean Israel Limited ("Energean Israel") signed a new GSPA with Sorek Energy Power Plant Ltd ("Sorek"). The contract is for the supply of gas to Sorek's new H-class power station, which is estimated to be operational in late 2029. Sorek is a nationally significant energy infrastructure project, aligned with a government resolution to expand natural gas-based generation capacity in response to Israel's expected growth in electricity demand.

The GSPA is for a term of ~15 years for a total contracted quantity of up to ~7.7 bcm, representing ~$1.4 billion in revenues over the life of the contract. The GSPA is for the supply of up to 0.5 bcm/yr once the new power station is operational, expected from late 2029, rising to up to 0.6 bcm/yr from September 2035 onwards, and includes interruptible volumes during the summer months between late 2029-2035. The contract contains provisions regarding floor pricing, take-or-pay and price indexation and has been signed at terms in line with Energean's other large, long-term gas contracts.

The agreement completes Energean's contracting of the three major new power generation projects expected to come online in Israel around the end of the decade. Alongside Kesem and Dalia II, the contracts add more than ~$5 billion of future contracted revenues, further strengthening the Company's contracted cash flow profile. Energean continues to evaluate additional long-term domestic gas contracts in Israel, supporting the commercialisation of future gas volumes within an increasing local demand environment.

Liquids sales

During H1 2026, Energean sold 1.88 mmbbl of hydrocarbon liquids through four cargoes, compared with 2.06 mmbbl through four cargoes in H1 2025. Liquids revenues increased to $156 million (H1 2025: $137 million), reflecting a 24% increase in realised liquids pricing to $82.9/bbl (H1 2025: $66.6/bbl), which offset lower year-on-year sales volumes.

Post-period end, on 13 July 2026, Energean safely completed commissioning of the second oil train on its Energean Power FPSO. This has expanded the total liquids processing capacity from 18 kbbl/d to 31 kbbl/d and further increased the proportion of the Company's revenues linked to Brent pricing. Liquids production has been tested at rates of up to 25 kbbl/d, representing a 160% increase compared with the H1 2026 average of 10 kbbl/d[23].

Development

Katlan phase 1A

Energean's deepwater Katlan project (working interest ("W.I.") 100%; operator) remains on budget and on schedule to deliver first gas in H1 2027. The project has made significant progress during 2026, with key milestones achieved to date including:

• Subsea infrastructure: The first two of four offshore installation campaigns have been successfully completed, including installation of the ~30 km production pipeline system, ~25 km Monoethylene Glycol ("MEG") flowline, and production riser. All major in-line subsea infrastructure has also been installed. The remaining subsea infrastructure is scheduled to be fully installed by around the end of 2026.
• Production wells: Drilling and completion activities for the Athena and Zeus production wells commenced during the period and completed in September 2026.
• FPSO upgrades: Post-period end, the Inlet Heaters Module (M01) and associated E-House (M09) were safely lifted onto the Energean Power FPSO. These modules are key components of the FPSO modifications required for the Katlan development and to support first gas in H1 2027. Integration and commissioning activities for these modules are ongoing. Remaining FPSO upgrade activities comprise installation of the MEG Reclamation Unit (M04) and Fired Heaters Module (M06), currently planned for 2027 and are not required to achieve first gas.

2027 growth drilling programme and Katlan Phase 1B

During the period, Energean advanced planning for Katlan Phase 1B, which will develop the Hera and Apollo fields on the Katlan lease. A rig contract was signed with Stena Drilling Limited for Energean's 2027 growth drilling programme, which includes the Hera and Apollo development wells for Katlan Phase 1B, as well as the Karish North-02 development well on the Karish and Karish North lease. In addition, Energean progressed planning and procurement activities for Phase 1B; post-period end, Energean signed a Letter of Award with TechnipFMC UK for the Phase 1B subsea installation scope.

Nitzana export pipeline

The Nitzana export pipeline is a new onshore pipeline that will connect Ramat Hovav to the border with Egypt in the Nitzana area. Energean has signed a transmission agreement securing capacity for the supply of up to 1 bcm/yr over a 15-year period. Nitzana is expected to be operational in late 2028.

During H1 2026, $10 million was incurred, bringing cumulative investments since the signing of the transmission agreement in Q4 2025 to around 60% of the total expected investment. The remaining investment will be made in accordance with the milestones set out in the agreement with INGL. Energean has signed a non-binding term sheet with an East Mediterranean client for the offtake of its exported gas.

Egypt

Egypt is a core country within Energean's portfolio and a priority growth market, supported by its significant resource potential and the country's strategic focus on increasing domestic energy production to strengthen energy security.

Production

Working interest production from Egypt averaged 27 Kboe/d (85% gas) during the period (H1 2025: 29 Kboe/d), reflecting successful mitigation of typical natural decline through production optimisation activities. No new production drilling activities were undertaken during the period while concession merger negotiations were ongoing.

Receivables

The Group's net receivables position (after provision for expected credit loss) at 30 June 2026 was $75 million, of which $25 million was classified as overdue. This represents a 64% reduction compared to 31 December 2025 ($209 million, of which $167 million was classified as overdue), reflecting collections of $226 million during the period. As a result, receivables have fallen to their lowest level since Energean acquired the Edison E&P portfolio in 2020.

Growth opportunities

Concession merger

Post-period end, Energean reached an agreement with EGPC on the main concession terms to consolidate its Abu Qir, North El Amriya and North Idku concessions into a single concession, subject to concession agreement finalisation and parliamentary ratification.

The new concession framework provides improved fiscal and commercial terms, including enhanced gas pricing, extending the economic life of existing assets and improving long-term cash flow generation. As a result, Energean has committed to invest up to an initial $150 million across production optimisation, development and exploration activities over a four-year period, which, subject to exploration success, could add up to 50 mmboe and double production over the following decade. It also unlocks exploration acreage, estimated to contain >4 Tcf[24], which includes approximately 3 Tcf[25] of gas in the deep horizon.

The commitment follows a period of tangible improvement in the Egyptian operating environment, including materially improved receivables collection as outlined above and continued support from the Egyptian authorities for upstream investment. Egypt remains a structurally attractive gas market, with growing demand and an increasing focus on maximising indigenous production to enhance energy security.

Through the merger, Energean believes it can generate greater value from its existing asset base, accelerate the development of additional resources and deliver attractive cash flow growth while supporting Egypt's long-term energy objectives.

Exploration

Exploration drilling on the onshore East Bir El-Nus block ("EBEN") (Energean: 50% W.I. operator, INA: 50% W.I.), targeting 5-10 mmbbl[26] of oil in the Gamma prospect, commenced in July 2026 and is progressing as planned. Operations to date have been executed safely with no incidents or environmental events recorded. Well results are expected towards the end of September 2026.

Europe

Production

Energean is focused on maximising value from its European portfolio (Italy, Greece, the UK and Croatia), which has access to European gas and Brent pricing. During H1 2026, working interest production averaged 10 kboed[27] (38% gas; H1 2025: 14 kboed) down 29% due primarily to Cassiopea, reflecting non-operated asset underperformance.

Italy

Energean has 36 production and development concessions in Italy, 13 of which it operates. During H1 2026, working interest production averaged 9 kboed (including Cassiopea; 43% gas). 53% of Italian output was generated from the Rospo Mare, Vega and Sarago Mare oil fields, all of which are operated by Energean with a 100% working interest. Higher realised liquids prices, up 38% year-on-year, supported a 28% year-on-year increase in oil revenues during the period.

In 2025, formal arbitration proceedings commenced between Energean Italy S.p.A. ("Energean Italy") and the Operator of the Cassiopea field. As a consequence of the operator's conduct - which is contested by Energean Italy - Energean Italy has not received production from the field during H1 2026 (refer to Note 25 to the interim consolidated financial statements). No other material developments occurred during the period and the arbitration remains ongoing.

Croatia

The Irena development (Energean, 70% W.I.) remains on schedule and on budget, with first gas expected in H1 2027. Fabrication of the new ~10-kilometre sales pipeline has been completed, with offshore installation scheduled for late September 2026. Jacket erection and topside assembly for the new offshore platform are progressing in Italy, with offshore installation expected in October 2026. Preparations for the offshore drilling campaign have also advanced, with the Labin jack-up rig secured to drill the Irena-3 development well from the new platform following installation, with drilling expected to commence towards the end of 2026. The rig is then expected to continue directly to the Izabela-9 exploration well, targeting approximately 25 Bcf of near-field gross gas prospective resources[28].

UK

Subsequent to period-end, the Garrow and Kilmar platform topsides and jackets were successfully removed and lifted onto Petrodec's OBNA jack-up vessel as part of Energean's operated UK decommissioning programme. The removal campaign, covering 3,373 tonnes of topside and jacket infrastructure, was completed safely and in accordance with the approved schedule and budget. Removal of the Wenlock platform is scheduled for October 2026.

Greece

In March 2026, Energean completed the farm-out of part of its interest in the Block 2 exploration licence to ExxonMobil, recognising $11 million of other operating income. The Group subsequently signed a rig contract with Stena Drilling for its 2027 growth drilling programme, which includes the Block 2 exploration well which is targeting ~9.5 Tcf of gross Pmean GIIP[29]. Energean will remain operator during the exploration phase, with exploration drilling anticipated to begin in Q2 2027.

2026 Guidance[30],[31]

FY 2026

Production

Financial Review

Revenue, production and commodity prices

Group working interest production averaged 124 Kboe/d[35] in H1 2026, 10% lower than H1 2025 (138 Kboe/d), with Israel continuing to represent more than 70% of total output. The reduction primarily reflects a temporary, government-mandated suspension of production in Israel between 28 February and 9 April 2026, following geopolitical escalations in the region. Production resumed promptly following the restart, with June output running ahead of budget as the field ramped back up. Excluding the impact of the government-mandated shutdown days in both periods, average working interest production was 3% higher in H1 2026 than H1 2025 (149 Kboe/d vs 144 Kboe/d). Refer to the "Production and Operational Update" section above for further details. The production mix remained broadly consistent at 83% gas and 17% liquids (H1 2025: 84% gas, 16% liquids). Overall, Group gas production was 10% lower and liquids production 6% lower than in the first half of 2025.

Group revenue and other income from production activities totalled $743 million, 8% below H1 2025 ($804 million), as lower volumes in Israel as a result of the temporary suspension of production were partially offset by the stronger pricing environment across the portfolio. Israel represented approximately 65% of Group revenue (H1 2025: 60%), while Italy's contribution reduced to approximately 19% (H1 2025: 25%), mainly reflecting a reduction in underlying Cassiopea production volumes year-on-year.

Liquids sales performed strongly, totalling $267 million (H1 2025: $234 million), driven by a materially higher weighted average realised liquids price of $79.6/bbl (H1 2025: $61.6/bbl), reflecting elevated Brent pricing during the period. This more than offset the lower liquids volumes in Israel arising from the temporary suspension. Reflecting the Group's active management of Brent price exposure, a gain of $2 million was recognised on Brent hedge positions closed during the period.

By contrast, the weighted average realised gas price was $4.8/mcf, 8% lower than in H1 2025 ($5.2/mcf). This reflected a shift in the sales mix towards Israel, where realised gas prices are lower, and away from Italy, where PSV prices were broadly stable at €44.1/MWh (H1 2025: €43.6/MWh). Group gas revenue declined 21% to $429 million, primarily reflecting lower volumes in Israel. In Italy, reported gas revenue also declined, though this partly reflects a presentational change: Cassiopea gas entitlement, previously recognised within gas revenue, is now recognised as other income from production activities under the non-cash settlement mechanism used while the dispute with the field operator remains ongoing. On a combined basis (gas revenue plus other income), total Italy production-related income decreased by $63 million year-on-year, reflecting lower underlying Cassiopea production volumes.

Cash production costs

Total cash production costs (including royalties) for the period decreased to $259 million (H1 2025: $272 million), with Israel accounting for 54% of the total costs. Excluding Israel, costs reduced to $118 million (H1 2025: $123 million), reflecting lower transportation, treatment, and royalty costs in Italy associated with reduced Cassiopea production volumes. Group unit costs increased to $10.9/boe (H1 2025: $10.2/boe), as lower production volumes in both Israel and Italy resulted in the Group's cost base being spread over a smaller production base. As outlined in note 5, royalties in Italy and Israel remain a significant component of production costs. Excluding royalties, production costs were $162 million (H1 2025: $175 million), equating to $6.6/boe (H1 2025: $6.4/boe). Despite the reduction in production volumes, the Group maintained strong cost discipline demonstrating the Group's ability to flex its cost base in response to lower throughput.

Adjusted EBITDAX

Adjusted EBITDAX of $478 million was 5% below H1 2025 (H1 2025: $505 million). Higher realised oil prices supported growth in Israel and Egypt. This was more than offset by a $37 million decline in Italy, reflecting the Cassiopea performance discussed above. The rest of the Group was broadly stable in aggregate.

Depreciation

Depreciation on production and development assets remained broadly consistent compared to the prior year at $189 million in H1 2026 (H1 2025: $194 million).

Exploration and evaluation expenditure and new ventures

During the period, the Group expensed $7 million (H1 2025: $4 million) for exploration and new venture evaluation activities reflecting the Group's ongoing assessment of growth opportunities. As with prior periods, this spend relates to early-stage technical, commercial, and due diligence work on a number of prospects, none of which are committed at this stage.

Other income

The Group recognised $11 million of other operating income from the Block-2 (Greece) farm-out to ExxonMobil, which completed in March 2026. An exploration well is planned on the block in Q2 2027, subject to permitting. Separately, the Group recorded $2 million of net reversals, including a $1 million reversal of a provision relating to tax litigation in Italy, with the remainder comprising minor releases of prior period accruals no longer required across other jurisdictions.

Other operating expenses

Other expenses were $1 million (H1 2025: $1 million), with the increase not material in relation to the Group's overall cost base.

Expected credit loss

A net expected credit loss reversal of $4 million (H1 2025: charge of $2 million) was recognised, reflecting an improvement in the cash collection environment in Egypt, where the Group's principal counterparty is the state owned Egyptian General Petroleum Corporation ("EGPC"). During H1 2026, EGPC made payments recovering approximately 75% of the aggregate opening receivable balance as at 31 December 2025 and sales recognised during the period, resulting in a significant reduction in the receivable balance subject to expected credit loss and a corresponding reduction in the allowance.

Net finance costs

Total finance costs in H1 2026 remained stable at $121 million (H1 2025: $128 million) reflecting the higher level of interest capitalised in Israel for Katlan and Nitzana projects. Total financing costs before capitalisation were $154 million (H1 2025: $144 million), mainly comprising $83 million in interest expense on Senior Secured notes, $46 million on debt facilities, and $21 million from the unwinding of discounts on long-term payables and decommissioning provisions. Net finance costs also reflect net foreign exchange gain of $6 million comprising a foreign exchange loss in Israel, mainly on the ILS-denominated portion of the Bank Leumi loan, offset by a gain at plc level on the EUR-denominated bond against the US dollar. Separately, the Group recorded finance income of $3 million, which includes interest income from time deposits.

Net gain on derivatives

The net gain on derivatives recognised in profit or loss was not material for H1 2026 (H1 2025: $3 million loss) as the Group's other hedging activity during the period was recognised within other financial statements line items, consistent with the nature of the underlying hedged item.

Taxation

The Group had a tax expense of $19 million in H1 2026 (H1 2025: $64 million), on a profit before tax of $178 million (H1 2025: $174 million), giving an effective tax rate of 11% (H1 2025: 37%). The reduction in the effective tax rate compared to H1 2025 was driven primarily by the recognition of $26 million of previously unrecognised deferred tax assets in Italy, relating to decommissioning provisions reflecting the current expectations of the forecast taxable profits. Following a reassessment of recoverability at H1 2026, the Group concluded that sufficient forecast taxable profits are now expected to be available against which these temporary differences can be utilised.

The current tax expense includes $26 million of tax expense in Israel (H1 2025: $29 million), a slight decrease reflecting reduced profitability of the Karish and Karish North operations following the temporary suspension of production at the Energean Power FPSO during the period. Egypt non-cash taxes of $17 million (H1 2025: $13 million) continued to be a significant component of the current tax charge.

The Group remains within the scope of the Pillar Two Model Rules from 1 January 2025 and has applied the mandatory temporary exception under IAS 12 from recognising and disclosing deferred taxes related to Pillar Two income taxes. There has been no change to the Group's assessment since 31 December 2025, and, including consideration of transitional safe harbour provisions, the Group does not expect a material exposure to Pillar Two top-up taxes. Accordingly, no current tax expense in respect of Pillar Two top-up taxes has been recognised in the period.

Profit after tax and earnings per share

Profit before tax of $178 million was broadly consistent compared to the prior year (H1 2025: $174 million), as a net foreign exchange gain and lower finance costs largely offset the impact of lower revenue. Profit after tax was $160 million (H1 2025: $110 million), reflecting the lower effective tax rate discussed above, primarily driven by the recognition of previously unrecognised deferred tax assets in Italy.

In H1 2026, basic earnings per share was $0.90 (H1 2025: $0.60). The increase is broadly in line with the growth in profit after tax, with the weighted average number of shares outstanding remaining largely unchanged period on period.

Operating cash flow

In H1 2026, the Group generated net operating cash inflows of $476 million compared with $555 million in H1 2025. Cash flow from operations before working capital movements was $452 million (H1 2025: $518 million). Working capital movements contributed a net inflow of $49 million (H1 2025: $148 million), including a reduction in trade and other payables, principally in Italy and Egypt, largely offset by strong collection of trade receivables, including recovery of historical amounts due from EGPC in Egypt in addition to receipts in respect of ongoing sales. Income tax paid in the period was $25 million (H1 2025: $111 million), with the prior period reflecting settlement of a significant element of Israel's 2024 tax liability in addition to payments relating to H1 2025 operations.

Capital Expenditures

Development capital expenditures totalled $350 million in the period (H1 2025: $299 million), primarily directed towards development projects in Israel ($301 million mainly related to the Katlan development and the Nitzana project, further details are available in the "Israel" section above) and Croatia ($14 million related to Irena development). Exploration and appraisal spend in H1 2026 was minimal ($3 million), reflecting some minor exploration activities in Israel and Egypt.

The Group continued to hedge foreign currency exposure on payments due under the Katlan Engineering, Procurement, Construction and Installation ("EPCI") contract. Positions that matured during the period delivered a $7 million gain, which reduced the reported cost of the related capital expenditure, reflecting the benefit of the Group's hedging programme in locking in favourable exchange rates.

Decommissioning provision

During the period, the decommissioning provision decreased by $16 million due to the updates to decommissioning cost estimates and revision of other relevant assumptions such as discount and inflation rates. A $2 million increase in the decommissioning provision (H1 2025: $4 million) was expensed during the period, primarily relating to Italy, due to a modest increase in the discount rate since year-end across all decommissioning-related assets. A further $11 million decrease in decommissioning provision, principally relating to Israel and Italy, was recognised as a reduction to the carrying value of the related property, plant and equipment.

In H1 2026, the Group invested $4 million in decommissioning works, comprising $1 million for the Wenlock and Tors projects in the UK, and $3 million in Italy, primarily for the Candela and Squalo Fratello Nord projects.

Net debt

As at 30 June 2026, net debt was $3,227 million (FY25: $3,255 million), consisting of total borrowings of $3,548 million including deferred amortised fees, offset by total cash of $321 million, including $6 million of restricted cash.

Total borrowings include the following drawn amounts:

• $2,000 million in Israeli senior secured notes;
• €400 million in corporate senior secured notes;
• €90.5 million from the Greek Black Sea Trade and Development Bank (BSTDB) loan and €9.5 million in Greek state loan notes (both equivalent to $115 million);
• $475 million and ILS 942 million (both equivalent to $750 million) drawn from Bank Leumi under the term loan agreement; and
• $246 million in other borrowings including under the corporate RCF.

Energean's floating interest rate exposure is limited to certain arrangements, namely the Greek BSTDB loan, the $750 million Bank Leumi term loan, the corporate RCF and other short-term bilateral agreements. All Senior Secured Notes, including both at Energean Plc and Energean Israel, carry fixed interest rates.

Shareholder Distributions

Energean returned $0.40 per share to shareholders in H1 2026, totalling $74 million, representing two-quarters of dividend payments. In H1 2025, Energean returned $0.60 per share.

Non-IFRS measures

The Group uses certain measures of performance that are not specifically defined under IFRS or other generally accepted accounting principles. These non-IFRS measures include adjusted EBITDAX, underlying cash cost of production and G&A, capital expenditure, net debt and leveraging.

Adjusted EBITDAX

Adjusted EBITDAX is a non-IFRS measure used by the Group to measure business performance. It is calculated as profit or loss for the period, adjusted for discontinued operations, taxation, depreciation and amortisation, share-based payment charge, impairment of property, plant and equipment, other income and expenses, net finance costs and exploration costs. The Group presents adjusted EBITDAX as it is used in assessing the Group's growth and operational efficiencies because it illustrates the underlying performance of the Group's business by excluding items not considered by management to reflect the underlying operations of the Group.

Cash cost of production

Cash cost of production is a non-IFRS measure that is used by the Group as a useful indicator of the Group's underlying cash costs to produce hydrocarbons. The Group uses the measure to compare operational performance period-to-period, to monitor cost and assess operational efficiency. Cash cost of production is calculated as cost of sales, adjusted for depreciation and hydrocarbon inventory movements.

Cash General & Administrative Expense (G&A)

Cash G&A excludes certain non-cash accounting items from the Group's reported G&A. Cash G&A is calculated as follows: administrative and distribution expenses, excluding depletion and amortisation of assets and share-based payment charge that are included in G&A.

Capital Expenditure

Capital expenditure is a useful indicator of the Group's organic expenditure on oil and gas assets and exploration and appraisal assets incurred during a period. Capital expenditure is defined as additions to property, plant and equipment and intangible exploration and evaluation assets less decommissioning asset additions, right-of-use asset additions, capitalised share-based payment charge and capitalised borrowing costs:

Net Debt

Net debt is defined as the Group's total borrowings less cash and cash equivalents. Management believes that net debt serves as a valuable indicator of the Group's indebtedness, financial flexibility, and capital structure because it reflects the level of borrowings after accounting for any cash and cash equivalents that could be utilised to reduce borrowings.

Going Concern

The Directors assessed the Group's ability to continue as a going concern over a going concern assessment period to 31 December 2027. As a result of this assessment, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future and for this reason they continue to adopt the going concern basis in preparing the condensed consolidated interim financial statements. Detail of the Group's going concern assessment for the period can be found within note 2.2 of the condensed consolidated interim financial statements.

Principal risks at half-year 2026 and key developments since the 2025 Annual Report

Effective risk management is fundamental to achieving Energean's strategic objectives and protecting its personnel, assets, shareholder value and reputation. Energean's risk management framework and process are described in detail between pages 65-79 in its 2025 Annual Report and Accounts. The principal risks and uncertainties facing the business are monitored on an ongoing basis in line with the UK Corporate Governance Code 2024. The Board has overall responsibility for determining the nature and extent of the risks it is willing to take in achieving the strategic objectives of the Group and ensuring that such risks are managed effectively.

Principal risks and uncertainties

The Board has reviewed the principal risks and uncertainties facing the Group for the remainder of the financial year. While the majority of the principal risks disclosed in the 2025 Annual Report remain relevant and materially unchanged, the Board has identified certain developments that have resulted in changes to the Group's principal risk profile, as described below.

Key developments in relation to Energean's risks

New principal risk: M&A strategy execution and value delivery

As the Group increasingly pursues inorganic growth opportunities across the Europe, Middle East and Africa region, the Board has identified "M&A strategy execution and value delivery risk" as a new principal risk.

This reflects the growing importance of acquisitions, strategic transactions and portfolio optimisation activities to the Group's long-term growth strategy. The risk encompasses transaction execution, regulatory approvals, integration planning and delivery, cost and schedule performance, value realisation, stakeholder management and post-transaction operational performance.

During the period, the Group announced the proposed acquisition of interests in certain offshore Angola assets. In August 2026, the Group was notified that Etu Energias had executed a sale and purchase agreement pursuant to its contractual pre-emption rights with respect to the Group's proposed acquisition of Chevron's interests in Blocks 14 and 14K, offshore Angola. As of the time of writing, the sale and purchase agreement between Energean and Chevron remains in effect until the sale and purchase agreement between Chevron and Etu Energias has been completed.

Geopolitical and security risks

Operations in Israel remain subject to elevated geopolitical and security risks. Production in Israel was temporarily suspended for 41 days between 28 February and 9 April 2026, following a directive from the Ministry of Energy and Infrastructure due to geopolitical escalations. Operations subsequently resumed safely and without incident. Energean continues to monitor the situation closely and maintains contingency plans, including security protocols for its workforce and personnel that prioritises the safety of its staff and contract personnel, and diversified logistic routes. It also maintains financial and structural resilience measures, including engagement with lenders and stakeholders to preserve covenant stability during potential disruption events, eligibility for applicable government compensation mechanisms in respect of qualifying war-related damage, and the active review and procurement of war-risk insurance solutions.

Changes to risk categorisation and nomenclature

The Board has also approved certain refinements to the naming and categorisation of principal risks to better reflect the Group's risk governance framework and underlying risk exposures. These changes are intended to improve clarity, accountability and reporting and do not, in themselves, indicate a change in the Group's overall risk profile.

The principal risks are now summarised as:

• Geopolitical and security risks
• Production downtime and operating efficiency risk
• Project delivery risk
• Subsurface risk
• M&A strategy execution and value delivery risk (new)
• Liquidity and market risks
• Non-operated assets and JV management risk
• Significant IT and OT cyber risk
• Legal, compliance, regulatory and financial crime risk
• Asset integrity, health, safety and environmental risk
• Climate change and energy transition risk

Emerging risks

Within the Company's enterprise risk management framework, emerging risks are considered as part of the identification phase. These are risks that cannot yet be fully assessed, risks that are known but are not likely to have an impact for several years, or risks which are unknown but could have implications for the business moving forward. During the second half of 2026, management will continue to monitor any relevant trends, enhancing proactive monitoring and scenario planning while exploring new opportunities.

Statement of Directors' responsibilities

The Directors confirm that, to the best of their knowledge:

• The condensed consolidated interim financial statements have been prepared in accordance with IAS 34 'Interim Financial Reporting' as adopted pursuant to UK-adopted international accounting standards.
• The interim management report includes a fair review of the information required by the Disclosure Guidance and Transparency Rules (DTR) 4.2.7R, namely an indication of important events during the six months ended 30 June 2026 and a description of the principal risks and uncertainties for the remaining six months of the financial year.
• The interim management report includes a fair view of the information required by the DTR 4.2.8R, including disclosure of related party transactions and any changes therein during the reporting period.

Casting in tables

Numbers outside of the unaudited consolidated interim financial statements, where applicable, are rounded to the nearest million US$ and therefore totals may differ in the order of a million US$.

INDEPENDENT REVIEW REPORT TO ENERGEAN PLC

Conclusion

We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2026 which comprises the interim consolidated income statement, the interim consolidated statement of comprehensive income, the interim consolidated statement of financial position, interim consolidated statement of changes in equity, the interim consolidated statement of cash flows and the related explanatory notes 1 to 28. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

Basis for Conclusion

Conclusions Relating to Going Concern

Responsibilities of the directors

Auditor's Responsibilities for the review of the financial information

Use of our report

Ernst & Young LLP

London

Interim Consolidated Income Statement

Six months ended 30 June 2026 (Unaudited)

Other comprehensive income:

Items that may be reclassified subsequently to profit or (loss)

Items that will not be reclassified subsequently to profit or (loss)

Adjustments to reconcile profit before taxation to net cash provided by operating activities:

*The presentation of the movement in restricted cash has been changed in the current period, refer to Note 2 for further details.

Corporate Information

Energean plc (the 'Company') was incorporated in England & Wales on 8 May 2017 as a public company limited by shares, under the Companies Act 2006. Its registered office is at One Great Cumberland Place, London, W1H 7AL, United Kingdom. The Company and all subsidiaries controlled by the Company, are together referred to as 'the Group'.

The Group has been established with the objective of exploration, production and commercialisation of crude oil, hydrocarbon liquids and natural gas in gas in the Europe, Middle East and Africa ("EMEA") region. Energean has operations in six countries: Israel, Egypt, Italy, Greece, Croatia and the UK.

The Group's subsidiaries and core assets, as of 30 June 2026, are presented in notes 27 and 28.

Basis of preparation

2.1 Basis of preparation

The unaudited condensed consolidated interim financial statements for the six months ended 30 June 2026 included in this interim report have been prepared in accordance with UK-adopted International Accounting Standard 34 'Interim Financial Reporting' ('IAS 34'), and, unless otherwise disclosed, have been prepared on the basis of the same accounting policies and methods of computation as applied in the Group's Annual Report for the year ended 31 December 2025.

The unaudited condensed consolidated interim financial statements have been prepared on a historical cost basis and are presented in US Dollars, which is also the Company's functional currency, rounded to the nearest thousand dollars ($'000) except where otherwise indicated. The US dollar is the currency that mainly influences sales prices, revenue estimates, and has a significant effect on the Group's operations. The functional currencies of the Group's main subsidiaries are Euro for Energean Italy Spa, Energean Sicilia Srl, Energean Oil & Gas S.A. and EnEarth Limited, $ for Energean Group Services Limited, Energean Israel Limited, Energean Egypt Limited, Energean E&P Holdings Limited, Energean Investments Limited, and Energean Capital Limited, and GBP for Energean UK Limited and Energean Exploration Limited.

The unaudited condensed consolidated interim financial statements do not constitute statutory accounts of the Group within the meaning of Section 435 of the Companies Act 2006 and do not include all the information and disclosures required in the annual financial statements. These financial statements should be read in conjunction with the Group's Annual Report for the year ended 31 December 2025, which were prepared in accordance with UK-adopted International Accounting Standards ('UK-adopted IAS'). These financial statements have been delivered to the Registrar of Companies. The auditor's report on those financial statements was unqualified, did not include a reference to any matters by way of emphasis and did not contain a statement under Section 498 (2) or Section 498 (3) of the UK Companies Act 2006.

In the period, the Group has changed the presentation of movements in restricted cash relating solely to debt servicing, specifically cash restricted under the terms of the Senior Secured Notes ahead of scheduled coupon payments, from investing activities to financing activities in the Statement of Cash Flows. Previously, such movements were presented within investing activities as movements between cash and cash equivalents and restricted cash. The Group considers that this change provides more relevant and reliable information, as the restrictions relate solely to the financing activity, being the servicing of debt under the Senior Secured Notes, and the revised presentation better reflects the nature of the underlying cash flows. In accordance with IAS 8, the comparative period has been restated. There is no impact on the total net increase or decrease in cash and cash equivalents, profit for the period, or the Statement of Financial Position for any period presented.

2.2 Going concern

The Group carefully manages the risk of a shortage of funds by closely monitoring its funding position and its liquidity risk. The Going Concern assessment covers the period up to 31 December 2027 'the forecast period'.

As of 30 June 2026, the Group's available liquidity was approximately $399 million. In addition to $315 million of cash and cash equivalents held by the Group at 30 June 2026, this available liquidity figure includes: (i) $37 million available under unsecured loan facility obtained in relation to the Nitzana project and $47 million under Revolving Credit Facility. In addition, the Group holds $6 million of restricted cash, principally comprising debt service reserve accounts.

The going concern assessment is founded on a cashflow forecast prepared by management and approved by the Board of Directors, which is based on a number of assumptions, most notably the Group's latest life of field production forecasts, budgeted expenditure forecasts, estimated of future commodity prices (based on recent published forward curves) and available headroom under the Group's debt facilities. The going concern assessment contains a "Base Case" and a "Reasonable Worst Case" ("RWC") scenario, as well as additional stress tests on production and pricing and a scenario assuming an Israel shutdown due to geopolitical risks.

Base Case assumes Brent at $83/bbl in 2026 and $75/bbl in 2027, and PSV at €52/MWh and €40/MWh in 2026 and 2027 respectively, with prices for gas sold assumed at contractually agreed prices for Egypt and Israel. Under the Base Case, sufficient liquidity is maintained throughout the going concern period.

The Group also routinely performs sensitivity tests of its liquidity position to evaluate adverse impacts that may result from changes to the macro-economic environment, such as a reduction in commodity prices and in production. These downsides are considered in the RWC scenario along with other assumptions. Following the drawdown of the $750 million senior-secured term loan with Bank Leumi as Facility Agent and Arranger in the second half of 2025, the Group has floating interest rate exposure, which continues to be reflected in the going concern assessment. The group also looks at the impact of changes or deferral of key projects and downside scenarios to budgeted production forecasts in the RWC.

The two primary downside sensitivities considered in the RWC are: (i) reduced commodity prices; (ii) reduced production - these downsides are applied to assess the robustness of the Group's liquidity position over the Assessment Period. In a RWC downside case, there are appropriate and timely mitigation strategies, within the Group's control, to manage the risk of funding shortfalls and to ensure the Group's ability to continue as a going concern. Mitigation strategies, within management's control, modelled in the RWC include deferral of discretionary capital expenditure on operated assets and/or management of controllable operating expenses to improve liquidity.

Under the RWC scenario, after considering mitigation strategies, liquidity is maintained throughout the going concern period.

In assessing the Group's resilience, the Board also considered downside scenario incorporating a prolonged suspension of production in Israel, reflecting the ongoing geopolitical uncertainty in the Middle East and the temporary suspension of Israeli production taking place in the beginning of 2026. This scenario was modelled across the full going concern horizon (until 31 December 2027) and assumes an extended period without Israeli revenues - a scenario which the Board considers to be remote and unrealistic. Notwithstanding its remote likelihood, and after taking into account available mitigating actions, the Group maintains adequate liquidity and covenant headroom throughout the assessment period.

Reverse stress testing was also performed to determine what production shortfall could need to occur for liquidity headroom to be eliminated. The conditions necessary for liquidity headroom to be eliminated are judged to have a remote possibility of occurring, given the diversified nature of the Group's portfolio and the "natural hedge" provided by virtue of the Group's fixed-price gas contracts in Israel. In the event a remote downside scenario occurred, prudent mitigating strategies, consistent with those described above, could also be executed in the necessary timeframe to preserve liquidity. There is no material impact of climate change within the Assessment Period and therefore, it does not form part of the reverse stress testing performed by management.

In forming its assessment of the Group's ability to continue as a going concern, including its review of the forecasted cashflow of the Group over the Forecast Period, the Board has made judgements about:

• Reasonable sensitivities appropriate for the current status of the business and the wider macro environment; and
• the Group's ability to implement the mitigating actions within the Group's control, in the event these actions were required.

After careful consideration, the Directors are satisfied that the Group has sufficient financial resources to continue in operation for the foreseeable future, for the Assessment Period from the date of approval of these unaudited condensed consolidated interim financial statements on 8 September 2026 to 31 December 2027. For this reason, they continue to adopt the going concern basis in preparing these condensed consolidated interim financial statements.

2.3 New and amended accounting standards and interpretations

The following amendments became effective as at 1 January 2026 :

• Amendments to IFRS 9 and IFRS 7: Classification and measurement of financial instruments;
• Annual improvements to IFRS accounting standards: Volume 11; and
• Amendments to IFRS 9 and IFRS 7: Contracts referencing nature-dependent electricity.

The adoption of the above amendments to UK-adopted IAS did not result in any material changes to the Group's accounting policies and did not have any material impact on the financial position or performance of the Group.

2.4 Standards issued but not yet effective

IFRS 18 Presentation and Disclosure in Financial Statements was issued by the IASB in April 2024 and is effective for annual reporting periods beginning on or after 1 January 2027, with full retrospective application required. The Group has not early adopted IFRS 18.

IFRS 18 will replace IAS 1 and introduces a revised structure for the statement of profit or loss, requiring all income and expenses to be classified into one of five categories (operating, investing, financing, income taxes and discontinued operations) and the presentation of two new mandatory subtotals: 'operating profit or loss' and 'profit or loss before financing and income tax'. The standard also introduces mandatory disclosure requirements for management-defined performance measures ('MPMs') and enhanced guidance on the aggregation and disaggregation of information in the financial statements. Consequential amendments are made to IAS 7, IAS 8, IAS 33 and IAS 34.

The Group has commenced its assessment of the impact of IFRS 18. The most significant area identified to date is the classification of Adjusted EBITDAX as a management-defined performance measure under IFRS 18. Adjusted EBITDAX is used by management in its external communications to communicate the underlying performance of the business, and the Group therefore expects to be required to present a reconciliation of Adjusted EBITDAX to the nearest IFRS 18-required subtotal, together with a description of the measure and the related income tax effect, in a new note to the financial statements.

Other significant areas of judgement identified to date include: the classification of net foreign exchange gains and losses into the new operating, investing and financing categories, given the Group's material non-US dollar monetary exposures (principally EUR and ILS); the classification of interest income on cash and short-term deposits, which is expected to move from finance income to the new investing category; the treatment of reclassification adjustments on settlement of the Group's cash flow hedging instruments; and the classification of the petroleum profits levy in Israel under the Income and Natural Resources Taxation Law, 5771-2011, which management expects to present within the income taxes category under IFRS 18, consistent with its treatment as a tax on the economic returns from hydrocarbon production. This conclusion will be confirmed as part of the Group's finalised IFRS 18 assessment by 31 December 2026.

As 2026 is the comparative period for the Group's first IFRS 18 financial statements, the Group's assessment and resulting accounting policy choices are expected to be substantially complete by 31 December 2026. The Group will provide further detail and a quantification of the expected impact of IFRS 18 on its primary financial statements in its annual financial statements for the year ending 31 December 2026.

The following amendments to IFRS Accounting Standards are also effective for annual periods beginning on or after 1 January 2027 and have not been early adopted:

• IFRS 19 Subsidiaries without Public Accountability: Disclosures and
• Amendments to IAS 21 Translation to a Hyperinflationary Presentation Currency.

No material impact on the Group's financial statements is anticipated from either amendment.

2.5 Approval of unaudited condensed consolidated interim financial statements by Directors

These unaudited condensed consolidated interim financial statements were approved by the Board of Directors on 8 September 2026.

Segmental Reporting

The information reported to the Group's Chief Executive Officer and Chief Financial Officer (together the Chief Operating Decision Makers) for the purposes of resource allocation and assessment of segment performance is focused on four operating segments: Europe (including Greece, Italy, UK and Croatia), Israel, Egypt and New Ventures. The Group's reportable segments under IFRS 8 Operating Segments are Europe, Israel and Egypt. New Ventures segment does not exceed the quantitative thresholds for reporting information about operating segments and has therefore been included within "Other" alongside inter-segment transactions.

Segment revenues, results and reconciliation to profit before tax

The following is an analysis of the Group's revenue, results and reconciliation to profit/ (loss) before tax by reportable segment:

Other & inter-segment transactions column refer to other segments transactions as well as transactions between the reported reportable segments. They are eliminated upon consolidation.

Finance costs, finance income, other income and expenses and share - based payment charge included in "Other & inter-segment transactions" are not allocated to individual segments as the underlying instruments are managed on a group basis.

Segment financial position

The following tables present assets and liabilities information for the Group's operating segments as at 30 June 2026 and 31 December 2025, respectively:

Other & inter-segment transactions column refer to other segments and transactions between the reportable segments. The oil & gas properties primarily reflect the fair value assessment by the Group following the acquisition of Israeli oil & gas assets in 2018.

Borrowings balance retained in Other & intersegment transactions column mainly comprises the loan balances held by Energean plc. Eliminations of cash management transactions within the Group are included in Other liabilities line in Other & inter-segment transactions column.Segment cash flows

The following tables present cash flow information for the Group's operating segments for six months ended 30 June:

Other revenue from production activities of $24.9 million (H1 2025: $nil) represents the non-cash settlement of outstanding joint operating liabilities in respect of the Cassiopea gas concession in Italy, recognised in accordance with the contractual valuation mechanism under the Joint Operating Agreement, consistent with the treatment described in the Note 30 in the Group's Annual Report for the year ended 31 December 2025. Refer to Note 25 for further details of the ongoing dispute and arbitration proceedings between Energean Italy and the operator.

In November 2025, ExxonMobil agreed to farm into Block 2, located in the northwest of the Ionian Sea. The transaction completed on 11 March 2026, resulting in the recognition of $11.1 million of other income in H1 2026. Refer to Note 11 for further details.

Other income from reversal of prior period accrual in 2025 mainly relates to $18.9 million reversed accrued expense no longer required in Egypt, following the lapse of the statute of limitations period under the Egyptian Commercial law.

Sales volumes for the six months ending 30 June (unaudited):

Financial instruments

The Group's objectives and policies for managing financial instrument risks are consistent with those described in the Annual Report for the year ended 31 December 2025. This note provides an update on significant developments in the Group's risk exposures and hedging activities during the six months ended 30 June 2026.

7.1 Fair values of financial assets and liabilities

The fair value of the bond is within level 1 of the fair value hierarchy. The fair values of other financial instruments not measured at fair value including cash and short-term deposits, trade receivables and trade and other payables equate approximately to their carrying amounts.

The Group also holds short-term foreign exchange derivative instruments that are not designated in formal hedge relationships, used to manage transactional currency exposures arising in the ordinary course of operations. These instruments are measured at fair value through profit or loss. The aggregate fair value of undesignated derivative instruments as at 30 June 2026 was $99 thousand, recognised as a current derivative asset in the consolidated statement of financial position. Fair value movements of $99 thousand were recognised in foreign exchange gain during the period.

7.2 Hedging activities

Hedge of net investment in foreign operations

Following the impairment charge recognised against the Argo-Cassiopea CGU in the year ended 31 December 2025, the net investment hedge of the EUR 400 million senior secured notes in Energean Italy S.p.A. ceased with effect from 31 December 2025. From 1 January 2026, foreign exchange movements on the retranslation of the EUR-denominated borrowing are recognised directly in the consolidated statement of profit or loss.

Derivatives designated as hedging instruments: cashflow hedges

The Group's cashflow hedge relationships during the six months ended 30 June 2026 comprised the following:

Commodity price risk

The Group actively manages its exposure to gas price volatility through a programme of collar instruments. The put and call options entered in April and May 2025 to hedge approximately 30% of anticipated Italian gas production against PSV price movements expired during the period. During H1 2026 the Group entered into new PSV collars and Brent crude oil collars to hedge a meaningful portion of anticipated gas production for the period from April 2026 to March 2027 and a smaller portion of forecasted oil production from April to September 2026 in Italy, consistent with the Group's ongoing commodity price risk management strategy. The Group also entered into and exercised a Brent swap and a collar in relation to a single cargo of Israeli liquids production during the period.

Foreign exchange risk - capital expenditure

The multi-currency forward contracts entered in January 2025 to hedge EUR, NOK and GBP payments under the Katlan EPCI contract remain active and continue to be designated as cashflow hedges of highly probable forecast purchases. These instruments are effective until August 2027.

Foreign exchange risk - financing

The Group entered into a cross-currency swap to partially hedge the foreign exchange risk arising from EUR-denominated coupon payments on the senior secured notes issued by Energean plc. The swap covers approximately 65% of the semi-annual coupon obligation and converts the hedged portion of EUR coupon payments into USD. The instrument is designated as a cashflow hedge of highly probable forecast financing outflows and matures in line with the coupon payment schedule of the underlying bond.

The Group is holding the following foreign exchange, commodity forward contracts and swap agreements on 30 June 2026:

The impact of hedging instruments on the statement of financial position is, as follows:

The effect of the cash flow hedge in the statement of profit or loss and other comprehensive income is, as follows:

No hedge ineffectiveness was recognised in profit or loss during H1 2026 in respect of the Group's cash flow hedges.

The movement in hedging reserves and foreign currency translation reserve during the six months ended 30 June 2026 is as follows:

Reconciliation of the total tax charge:

The tax rate applied to the Group's profits in preparing the reconciliation below is the main corporation tax rate of 25.0% applicable in the United Kingdom.

The effective tax rate for the period is 11% (June 2025: 37%). The tax (charge)/ credit of the period can be reconciled to the profit per the unaudited interim consolidated income statement as follows:

30 June (Unaudited)

Note A: The Group has not recognised deferred tax assets relating to current-year tax losses and other temporary differences arising in the UK ($5.8 million), Cyprus ($0.8 million) and Greece ($0.4 million), in line with the latest forecasts and assumptions regarding future taxable profits.

Note B: During H1 2026, the Group recognised $26 million of previously unrecognised deferred tax assets in Italy, principally relating to decommissioning-related temporary differences. The recognition reflects updated evidence supporting the recoverability of these deferred tax assets, including production performance across the Group's Italian portfolio and the resulting enhancement of forecasts of future taxable profits. Based on this reassessment, management concluded that it is probable that sufficient taxable profits will be available to utilise the associated deductible temporary differences. In addition, during the period, Italy utilised previously unrecognised temporary differences of $5.5 million, mainly relating to property, plant and equipment.

There are no income tax consequences attached to the payment of dividends in either 2026 or 2025 by the Group to its shareholders.

The Group is within the scope of the Pillar Two Model Rules starting from 1 January 2025. Legislation implementing these rules has been enacted or substantively enacted in a number of jurisdictions in which the Group operates. The Group has applied the mandatory temporary exception under IAS 12 from recognising and disclosing deferred taxes related to Pillar Two income taxes.

The Group has performed an assessment of its potential exposure to Pillar Two top-up taxes. Based on the analysis performed using information currently available, including consideration of transitional safe harbour provisions where applicable, the Group does not expect a material exposure to arise. In jurisdictions where the safe harbour provisions are not met, the Group does not expect any material top-up tax exposure. Accordingly, no amount has been recognised in the consolidated financial statements for the period.

The Group will continue to monitor developments in legislation, guidance and the geographic mix of earnings, which may impact future periods.

Earnings per share

Basic earnings per ordinary share amounts are calculated by dividing net income for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year.

Diluted income per ordinary share amounts is calculated by dividing net income for the year attributable to ordinary equity holders of the parent by the weighted average number of ordinary shares outstanding during the year plus the weighted average number of ordinary shares that would be issued if dilutive employee share options were converted into ordinary shares.

30 June (Unaudited)

Included in the carrying amount of leased assets at 30 June 2026 are right of use assets related to Oil and gas properties and Other property, plant and equipment of $15.4 million and $11.9 million respectively (31 December 2025: $37.0 million and $3.5 million respectively). The depreciation charged on these classes for the six-month ending 30 June 2026 were $8.9 million and $3.0 million respectively (six months ended 30 June 2025: $6.5 million and $2.8 million).

The additions to Oil & gas properties for the period of six months ended 30 June 2026 are mainly due to development costs of Katlan ($267 million) in Israel, and the Irena development in Croatia ($14 million).

Borrowing costs capitalised for qualifying assets, included in oil & gas properties, for the six months ended 30 June 2026 amounted to $30.4 million (30 June 2025: $15.5 million). The weighted average interest rates used was 7.46% for the six months ended 30 June 2026 (30 June 2025: 5.34%).

No indicators of property, plant and equipment impairment were noted on 30 June 2026.

Intangible assets

In November 2025, ExxonMobil agreed to farm into Block 2, located in the northwest of the Ionian Sea. Following receipt of government approval and an extension of the licence (as requested by Energean and HELLENiQ ENERGY Upstream), the transaction completed on 11 March 2026, during the current reporting period. Following completion, the participating interests in the licence are: Energean 30% (Operator), ExxonMobil 60%, and HELLENiQ ENERGY Upstream 10%. Energean remains Operator of the concession through the exploration phase, during which an exploratory well is expected to be drilled in early 2027, subject to permitting. At completion, Energean received consideration in respect of costs incurred prior to completion of the farm-out on 11 March 2026 resulting in the recognition of $11.1 million of other income in H1 2026.

No indicators of intangible assets impairment were noted on 30 June 2026.

Net deferred tax (liability)/ asset

As of June 2026 the Group had gross total unused tax losses of $1,066.5 million (as of 31 December 2025: $1,169.2 million) available to offset against future profits and other temporary differences. The Group has not recognised deferred tax on tax losses and other differences of $1,062.4 million.

In Greece and the UK, the net DTA for carried forward losses recognised in excess of the other net taxable temporary differences was $119.6 million and $21.1 million (2025: $121.4 million and $22.1 million) respectively.

Greek tax losses (Prinos area) can be carried forward without limitation up until the relevant concession agreement expires (by 2049), whereas, the tax losses in Israel, Italy and the United Kingdom can be carried forward indefinitely. Based on the Prinos area forecasts including the Epsilon development with first oil expected 2029, the deferred tax asset is fully utilised by 2038. Finally, in the UK, decommissioning losses are expected to be tax relieved up until 2030 in accordance with the latest taxable profits forecasts.

At June 2026, the gross amount and expiry dates of losses available for carry forward are as follows:

Note A: Mainly comprises tax losses generated in the Republic of Cyprus ($34 million), the UK ($25 million), and Greece ($15 million) relating to trading losses that cannot currently be utilised against profits from the Prinos asset.

Note B: Tax losses ring-fenced to the Prinos asset in Greece, which can be carried forward until the expiry of the relevant licences, i.e. by 2049.

Note C: Comprises Italian tax losses of $11 million, for which a deferred tax asset has been recognised, and UK tax losses of $70 million, for which no deferred tax asset has been recognised; both can be carried forward indefinitely.

There are no income tax consequences attached to the payment of dividends by the Group to its shareholders. As a result of exemptions on dividend from subsidiaries and capital gains on disposal there are no significant taxable temporary differences associated with investments in subsidiaries, branches, associates and interests in joint arrangements.

Cash and cash equivalents

Bank deposits comprise deposits and other short-term money market deposit accounts that are readily convertible into known amounts of cash. The effective interest rate on short‑term bank deposits was 4.29% for the six months period ended 30 June 2026 (H1 2025: 4.22%).

Restricted Cash

In addition to cash restricted in relation to letters of credit issued in Egypt, restricted cash comprises cash retained under the Israel Senior Secured Notes and the Greek State Loan requirement as follows:

Current:

The current portion of restricted cash at 30 June 2026 was $2.5 million (31 December 2025: $99.4 million). It mainly relates to the September 2026 coupon payment on Senior Secured Notes.

Non-Current:

The cash restricted for more than 12 months after the reporting date was $3.2 million (31 December 2025: $3.3 million) mainly comprising $2.3 million (31 December 2025: $2.3 million) held on the Interest Service Reserve Account ('ISRA') in relation to the Greek Loan Notes and $0.7 million (31 December 2025: $0.8 million) for Prinos Guarantee.

Inventories

The decrease in trade receivables during the period was primarily driven by improved collections in Egypt, including a $125 million one-off recovery received in April 2026 in respect of amounts previously outstanding from the Egyptian General Petroleum Corporation ("EGPC"), together with continued monthly cash collections in respect of ongoing sales. As a result, overdue receivables in Egypt reduced to $25.0 million at 30 June 2026 (31 December 2025: $166.8 million).

Share capital

The below table outlines the share capital of the Company:

Dividends

In line with the Group's dividend policy, Energean returned $0.40/share to shareholders during the reporting period, representing two-quarters of dividend payments (6 months ended 30 June 2025: $0.60/ share).

Non-current

Bank borrowings - after two years but within five years

The Group's borrowing facilities and associated security arrangements are described in the Annual Report for the year ended 31 December 2025. The following provides an update on significant developments during the six months ended 30 June 2026.

At 30 June 2026, the Group holds $2.0 billion in aggregate principal amount of senior secured notes, issued in three series as follows:

• $625 million, issued on 24 March 2021, maturing on 30 March 2028, with a fixed annual interest rate of 5.375%.
• $625 million, issued on 24 March 2021, maturing on 30 March 2031, with a fixed annual interest rate of 5.875%.
• $750 million, issued on 11 July 2023, maturing on 30 September 2033, with a fixed annual interest rate of 8.5%.

The interest on each series is paid semi-annually on 30 March and 30 September. The notes are listed for trading on the TACT Institutional of the Tel Aviv Stock Exchange Ltd (TASE), and the TASE-UP for the 2023 issuance.

The EUR 400 million senior secured notes issued on 10 November 2025, maturing in 2031 at a fixed annual interest rate of 5.625%, and the $750 million senior-secured term loan with Bank Leumi, remain in place and continue in accordance with their terms.

The $125 million unsecured facility, originally signed in April 2025, was amended in March 2026 to extend its maturity to 15 March 2027, with an option at the Company's discretion to extend to 15 September 2027. As a result of this amendment, the facility has been reclassified from current to non-current borrowings in the period.

The Bank Hapoalim $70 million unsecured nine-year term loan, entered into in October 2025 to fund the Group's share of construction costs in the Nitzana project, continues to be drawn as project payments progress. As at 30 June 2026, $33.0 million has been drawn under this facility.

The BSTDB facility of €90.5 million entered into by Energean Oil and Gas S.A. continues in line with its contractual maturity to 2030. Following the resumption of production at Prinos in February 2026, the facility has been reclassified from current to non-current borrowings in the period. Separately, prior to 30 June 2026, Energean Oil and Gas S.A. completed the sale of a fixed asset (a jacket structure) to a fellow Group company, EnEarth, in connection with a carbon storage project; as an intragroup transaction, this has no impact on the Group's consolidated results. Under the terms of the facility agreement, proceeds from this type of disposal are required to be used to partially repay the loan. Accordingly, $18.3 million of the facility has been reclassified to current borrowings at 30 June 2026, reflecting this mandatory repayment obligation.

The $300 million Revolving Credit Facility, extended to September 2028 in August 2025, remains available. As at 30 June 2026, $88.0 million was drawn under the facility (2025: $130.6 million).

There have been no other material changes to the Group's borrowing facilities or security arrangements during the six months ended 30 June 2026.

Capital management

The Group defines capital as the total equity and net debt of the Group. Capital is managed in order to provide returns for shareholders and benefits to stakeholders and to safeguard the Group's ability to continue as a going concern.

Energean is not subject to any externally imposed capital requirements. To maintain or adjust the capital structure, the Group may put in place new debt facilities, issue new shares for cash, repay debt, engage in active portfolio management, adjust the dividend payment to shareholders, or undertake other such restructuring activities as appropriate.

Decommissioning provision:

The decommissioning provision represents the present value of decommissioning costs relating to oil and gas properties, which are expected to be incurred up to 2052, when the producing oil and gas properties are expected to cease operations. The decrease in the estimate is primarily due to changes in the discount rate and inflation assumptions as of 30 June 2026.

The principal assumptions used in determining decommissioning obligations for the Group are shown below:

Payables to partners under the JOA include both payables and working capital estimates provided by the operators.

Deferred income mainly comprises 'take-or-pay' payments received in Israel ($5.9 million) and government grants received for the CCS Project in Greece ($8.3 million).

Other payables primarily consist of royalties accrued in Israel (H1 2026:$ 35.6 million, 31 December 2025: $36.8 million) and in Italy (H1 2026: $27.4 million, 31 December 2025: $27.9 million).22. Other non-current liabilities

Energean Long Term Incentive Plan (LTIP)

Under the Energean plc's 2018 LTIP rules, senior executives may be granted conditional awards of shares or nil cost options. Nil cost options are normally exercisable from three to ten years following grant provided an individual remains in employment. Awards are subject to performance conditions (including Total Shareholder Return (TSR) normally measured over a period of three years. Vesting of awards or exercise of nil cost options is generally subject to an individual remaining in employment except in certain circumstances such as good leaver and change of control. Awards may be subject to a holding period following vesting. No dividends are paid over the vesting period; however, Energean's Board may decide at any time prior to the issue or transfer of the shares in respect of which an award is released that the participant will receive an amount (in cash and/or additional shares) equal in value to any dividends that would have been paid on those shares on such terms and over such period (ending no later than the Release Date) as the Board may determine. This amount may assume the reinvestment of dividends (on such basis as the Board may determine) and may exclude or include special dividends.

The weighted average remaining contractual life for LTIP awards outstanding at 30 June 2026 was 1.5 years, number of shares outstanding 2,652,673 and weighted average price of $11.8.

Deferred Share Bonus Plan (DSBP)

Under the DSBP, a portion of any annual bonus of a Senior Executive nominated by the Remuneration & Talent Committee, may be deferred into shares. Deferred awards are usually granted in the form of conditional share awards or nil-cost options (or, exceptionally, as cash-settled equivalents). Deferred awards usually vest two years after award although may vest early on leaving employment or on a change of control.

The weighted average remaining contractual life for DSBP awards outstanding at 30 June 2026 was 1.2 years, number of shares outstanding 366,051 and weighted average price of $10.89.

Related parties

Balances and transactions between the Company and its subsidiaries, which are related parties, have been eliminated upon consolidation and are not disclosed in this note.

There have been no significant changes to related party transactions since 31 December 2025, refer to note 29 in the 2025 Annual Report and Accounts for more information. The Directors of Energean Plc are considered to be the only key management personnel as defined by IAS 24.

Commitments and contingencies

In acquiring its oil and gas interests, the Group has pledged that various work programmes will be undertaken on each permit/interest. The exploration and development capital commitments in the following table are an estimate of the net cost to the Group of performing these work programmes:

As of 30 June 2026, $1.0 million of capital commitments is towards Governments (31 December 2025: $1.4 million). An amount of $12.2 million (31 December 2025: $13.8 million) pertains to capital commitments with partners based on future work programs for the development of the Scott field in the United Kingdom and the second phase of drilling at Block 2 in Greece.

Open guarantees at 30 June 2026 comprise the following:

• Karish and Tanin Leases ($25 million) - As required by the Karish and Tanin Lease deeds, the Group provided the Ministry of National Infrastructures, Energy, and Water with bank guarantees for each lease. These guarantees are valid until June 2027.
• Blocks 23 and 31 ($13 million) - To meet the conditions for obtaining exploration and appraisal licenses, the Group provided the Ministry of National Infrastructures, Energy, and Water with bank guarantees covering all mentioned blocks. They are valid until June 2027.
• Katlan lease ($10 million) - As required by the Katlan Lease deeds, the Group provided the Ministry of National Infrastructures, Energy, and Water with bank guarantee. This guarantee is valid until January 2029.
• Nitzana project ($39 million) - The Group has provided guarantees to INGL in relation to Nitzana project. These guarantees were issued in November 2025 and are valid until November 2026.
• Israel Other ($3 million) - The Group has provided various bank guarantees to third parties in Israel as part of ongoing operations.
• United Kingdom ($121 million) - The Group has issued letters of credit for United Kingdom decommissioning obligations and other obligations under the United Kingdom licenses.
• Greece ($5 million) - The Group issued letters of credit ($1 million) to cover exploration obligations under the Prinos license and in regard to its gas and electricity contracts in Greece. In March 2026 the Group also provided a bank guarantee to the Greek state in regards to the second phase of Block 2 ($4 million).
• Cyprus ($26 million) - As disclosed in the Group's 2025 Annual Report, on 12 March 2026 the Group announced that it had signed an agreement to acquire Chevron's 31% operated interest in Block 14 and 15.5% non-operated interest in Block 14K, offshore Angola. Completion remains subject to government and regulatory approvals and the waiver of applicable pre-emption rights. In connection with the arrangements under the sale and purchase agreement, in March 2026 the Group issued a letter of credit of $26 million. The letter of credit is contingent on completion of the Angola transaction. As set out in note 26, the transaction was pre-empted by an existing partner in August 2026 and the letter of credit was released in the same month.
• Egypt ($6 million) - The total capital commitments in Egypt amounted to $6.0 million, with $4.8 million already spent as of 30 June 2026. The Group is awaiting clearance from EGPC, which is expected upon the completion of all commitments.
• Italy ($12 million) - The Group has issued guarantees primarily in favour of port authorities and counterparties in Italy to secure concession rights, field-related obligations, lease commitments and certain service contracts.

Legal cases and contingent liabilities:

The Group's legal cases and contingent liabilities are described in the Annual Report for the year ended 31 December 2025, refer to note 30. The most significant matter relates to the ongoing arbitration proceedings between Energean Italy S.p.A. and the operator of the Cassiopea gas concession in Italy. There have been no material developments in the arbitration during the six months ended 30 June 2026. The tribunal is in the process of appointing a technical expert, and the Group continues to await the outcome of that process. The Group has continued to apply the same accounting treatment as at 31 December 2025, recognising the retention of production by the operator as a non-cash settlement of outstanding joint operating liabilities, with a corresponding reduction to trade payables and recognition of other income from production activities.

Subsequent events

In August 2026, the Group was notified that Etu Energias had executed a sale and purchase agreement pursuant to its contractual pre-emption rights with respect to the Group's proposed acquisition of Chevron's interests in Blocks 14 and 14K, offshore Angola. Etu Energias is an existing partner in both licenses. Following this outcome, the $26 million letter of credit recorded by the Group in support of its bid was released in the same month.

In September 2026, the Group incorporated Energean Holdings Limited and Energean Holdings II Limited, both ultimately wholly-owned by Energean plc, in England & Wales, as part of the Group's ongoing corporate structuring activities.

Subsidiary undertakings

At 30 June 2026, the Group had investments in the following subsidiaries:

A joint relinquishment application in respect of Carlo, Clotilde e Didone (Italy) was submitted to MASE on 25 May 2026 and remains subject to Government approval as at the date of these financial statements.

Exploration:

[1] Average Group August 2026 production (including Cassiopea) was 165 Kboe/d and reflects the planned shutdown for the first Katlan heavy lift operation between 23 - 26 August 2026.

[2] Guidance excludes Cassiopea.

[3] Internal estimate includes prospectivity on existing licences and is based on Pmean Gas Initially In Place ("GIIP"). Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success.

[4] Includes Cassiopea.

[5] Cash cost of production is defined later in the financial review.

[6] Cash G&A is defined later in the financial review.

[7] Adjusted EBITDAX is defined later in the financial review. Energean uses adjusted EBITDAX as a core business KPI.

[8] Leverage calculated using last 12-months average Adjusted EBITDAX.

[9] Production includes Cassiopea (2 Kboe/d net to Energean's 40% working interest in H1 2026; H1 2025: 6 Kboe/d).

[10] Sales volumes are reported on a net entitlement basis in Egypt and excludes Cassiopea volumes from 1 October 2025 (refer to Note 30 in the Group's Annual Report for the year ended 31 December 2025 and Notes 4 and 25 to the interim condensed consolidated financial statements). Accordingly, Cassiopea revenues in H1 2026 are presented within 'Other revenue from production activities', whereas in H1 2025 they were presented within 'Revenue from gas sales'.

[11] Guidance excludes Cassiopea.

[12] Average Group August 2026 production (including Cassiopea) was 165 Kboe/d and reflects the planned shutdown for the first Katlan heavy lift operation between 23 - 26 August 2026.

[13] Excludes flux revenues in Italy.

[14] Internal estimate includes prospectivity on existing licences and is based on Pmean GIIP. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success.

[15] Actuals include capitalised borrowing costs and management services, not included in the FID amount.

[16] Energean has a 30% working interest in the Block 2 licence. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success.

[17] Includes flux costs in Italy.

[18] Free cash flow is defined as cash flow from operating activities less cash flow for investing activities.

[19] Energean has a 30% working interest in the Block 2 licence. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success.

[20] Production includes Cassiopea (2 Kboe/d net to Energean's 40% working interest in H1 2026; H1 2025: 6 Kboe/d; 8-months to 31 August 2026: 2 Kboe/d).

[21] Guidance excludes Cassiopea.

[22] Average Group August 2026 production (including Cassiopea) was 165 Kboe/d and reflects the planned shutdown for the first Katlan heavy lift operation between 23 - 26 August 2026.

[23] Includes temporary suspension between 28 February and 9 April 2026. Excluding this shutdown, Israel liquids production averaged 13 kbbl/d in H1 2026.

[24] Internal estimate includes prospectivity on existing licences and is based on Pmean GIIP. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success.

[25] Internal estimate based on Pmean GIIP.

[26] Internal estimate based on Pmean prospective resources, shown net of Energean's 50% working interest and after application of recovery factors, but before chance of success.

[27] Production includes Cassiopea (2 Kboe/d net to Energean's 40% working interest in H1 2026; H1 2025: 6 Kboe/d).

[28] Internal estimate based on Pmean prospective resources, with gross volumes shown (i.e. before Energean's 70% working interest) and after application of recovery factors, but before chance of success.

[29] Energean has a 30% working interest in the Block 2 licence. Pmean GIIP estimates are presented on an unrisked basis and therefore do not incorporate recovery factors or chance of success.

[30] Guidance excludes Cassiopea.

[31] Development and production capital expenditure, exploration expenditure and decommissioning expenditure guidance are presented on an accrual basis and not on a cash basis.

[32] Includes 4.7-4.9 bcm of gas. SCM to BOE conversion factor for Israel used is 153.78.

[33] Note that flux in Italy is not reflected in the production guidance but is included in sales revenue actuals.

[34] Guidance excludes $70-75 million of contingent Prinos Carbon Storage expenditure which is expected to be funded by grants.

[35] Energean Group including gas production from Cassiopea in Italy.